Well tool safety joint

ABSTRACT

A well tool safety joint according to the following technical disclosure includes an upper member connected to the pipe string and having a swivel coupling to a lower member. The lower member is constituted by separable parts connected by a left-hand thread. A one-way clutch coacts between the upper and lower members to enable right-hand rotation of the lower member relative to the upper member but to prevent right-hand rotation of the upper member relative to the lower member, so that righthand rotation of the upper and lower members by the pipe string will effect unthreading of the left-hand connection in the event that one of the separable parts becomes lodged in the well.

United States Patent lnventor Albert A. Mullins Richmond, Tex. Appl. No. 844,015 Filed July 23, 1969 Patented Jan. 5, 1971 Assignee Schlumberger Technology Corporation New York, N.Y.

a corporation of Texas WELL TOOL SAFETY JOINT I 9 Cla1ms,$ Drawing Figs.

US. Cl 166/ 237,

i 192/16-- Int. Cl E211) 23/00 I 132115-23/00 Field otSearch ..j .if'l66/237,

References Cited UNITED STATES PATENTS Primary Examiner- David H. Brown Attorneys- Ernest R. Archambeau, Jr., William .1. Beard,

David L. Moseley, Edward M. Roney, William R. Sherman and Stewart Moore "ABSTRACT: A well tool safety joint according to the following technical disclosure includes an upper member connected .to the pipe string and having a swivel coupling to a lower member. The lower member is constituted by separable parts "connected by a left-hand thread. A one-way clutch coacts between the upper and lower members to enable right-hand rotation of the lower member relative to the upper member but to prevent right-hand rotation of the upper member relative to the lower member, so that right-hand rotation of the upper and lower members by the pipe string will effect unthreading of the left-hand connection in the event that one of the separable parts becomes lodged in the well.

ATENIEU JAN 5 l97| SHEET 2 0F 2 Albert A, Mullins INVENTOR ATTORNEY WELL TOOL SAFETY JOINT This invention relates generally to well tools used in well bores, and more specifically to a safety coupling to enable selective release of tubular telescoping members in a well bore.

A well packer of the type shown in US. Pat. application Ser. No. 673,175, Berryman, filed Oct. 5, 1967, now U.S. Pat. No. 3,465,821 and assigned to assignee of the present invention, has a rotary valve which can bemoved between positions opening and closing a flow passage through the mandrel in response to upward and downward movement of the tubing string at the top of the well bore. Valve actuation is accomplished through use of an operatorextending into the flow passage and having a swivel coupling to the lower end of the pipe string. An index slot system that cooperates with pins on the mandrel causes the operator and valve sleeve to rotate through a sequence of turning motions as the pipe string is worked up and down. The valve operator can be released from the flow passage to enable removal of the pipe string from the well, and can be reinserted into the flow passage to further operate the valve as desired.

As disclosed in the aforementioned patent, a safety coupling is included as a precaution in the event that sedimentation or debris should'cause the operator to become lodged within the packer mandrel. The safety coupling'includes a split sleeve threaded to feed threads on one member of the swivel and slidably keyed to the other member so that rotation of the operator as the valve is moved causes the sleeve to feed to an inactive position enabling unimpeded relative rotation. In this position, the split sleeve is against a-stop and expands and ratchets over the feed threads during continued rotation.

. However, should the operator become lodged for any reason,

the pipe string can be rotated to the right, causing the split sleeve to feed against another stop and-underneath a cam locking surface to prevent expansion thereof. In this condition the split sleeve prevents relative rotation of, the swivel members so that torque can be applied therethrough to unthread a left-hand connection between the swivel and the operator.

high torsion load is required to break out the left-hand joint,

the sleeve may expand somewhat, resulting in stripping of the feed threads. Moreover, a significant amount of torque is required in the inactive position of the split sleeve to cause the sleeve to expand and ratchet over the feed threads. This can cause a buildup of residual torque in the system which may interfere with proper operation of the index system.

Accordingly, it is an object of the present invention to provide a new and improved safety coupling structure to enable I selective release of tubular telescoping members in a well bore. The safety'coupling is positive in operation and efiicient in transmitting torque and is constructed and arranged to minimize residual torque in its operation so as not to interfere withthe operation of an index system which may be associated therewith.

This and other objects are attained in accordance with the concepts of the present inventionby an apparatus comprising a first member adapted for connection to a pipe string extending upwardly to the top of the well bore. A second member is provided with a swivel coupling to said first member and is rotatable relative thereto. A clutch assembly on the members enables unrestricted rotation of the second member relative to the first member in one rotational direction. However, by rotating the first member by the pipe string relative to the second member in the same direction, the clutch assembly will engage to transmit torque between the members and enable release of a rotationally releasable connection between the second member and a third member.

The clutch assembly comprises atoothed ring slidably and corotatively secured to the inner member, and biasing means for urging said ring toward ngagement with a toothed portion of said outer member. The teeth on said ring and outer member have axially disposed coengageable surfaces for transmitting torque to said outer member in response to rotation of said inner member by the pipe string in one rotational direction. The teeth also have coengageable inclined surfaces facing away from said axial surfaces to enable ratcheting of said teeth over one another in response to rotation of said outer member relative to said inner member in said one rotational direction. A rotationally releasable means couples said second member to a third member that is telescopically disposed within an anchored member in the well bore, so that rotation of said first and second members by the pipe string relative to said third member, in the event that said third member becomes lodged, will release said connection to enable withdrawal of the pipe string from the well.

The present invention has other aspects and advantages which will become more clearly apparent in connection with the following detailed description. A preferred embodiment 15 shown in the accompanying drawings,in which:

FIGS. 1A and 1B are longitudinal sectional views, with portions in side elevation, of an apparatus which embodies the principles of the present invention with parts in relative positions for lowering into a well bore, FIG. 13 forming a lower continuation of FIG. 1A;

FIG. 2 is an isometric view of the rotary valve element;

FIG. 3 is a fragmentary developed view of a coupling mechanism used with the present invention;

FIG. 4 is a fragmentary developed view of the index slot system used with the present invention; and

FIG. 5 is an enlarged cross section view of the clutch system of the present invention.

With initial reference to FIGS. 1A and 1B, apparatus which will illustrate the principles of the present invention includes a mechanical setting tool A and a well packer B having a valve system C. The setting tool A is utilized in setting the packer B in a well bore so that the packer B can function to pack-off the well bore. The valve system C controls fluid communication to the well bore below the packer B. The entire apparatus can be lowered into the well on a running-in string 10 of tubing or drill pipe which provides a fluid conduit extending to the top of the well, as well as a mechanical member which can be manipulated at the top of the well bore to effect operation of the setting tool A and the valve assembly C. As shown in FIG. 1B, the packer B has a central body or mandrel 11 having a bore 12 which provides a fluid passageway and further has a lower guide portion 13 which supports lower slips 14. The slips [4 can take any desired form, such as frangible, segmented, or integral expansible type slips. A lower expander cone 15 is arranged to shift the lower slips l4 outwardly and a conventional packing structure 16 surrounds the mandrel 11 between the lower expander cone and an upper expander cone 17. Typical antiextrusion rings 18, 18a can confine the end portions of the packing I6, and shear pins 19, or other suitable means can releasably couple the expander cones I5 and 17 to the mandrel 11 to control the relative motion sequence between parts in any desired manner. A conventional split ratchet ring 20 is arranged between the upper expander cone 17 and the mandrel l1 and cooperates with ex ternal teeth 21 on the mandrel to trap compression loading in the packing structure 16 when the well packer B is set.

The lower guide portion I3 of the mandrel 11 is constituted as a valve body having a central flow passage 24 which is closed at its lower end. Diametrically opposed side ports 26 in the valve body 13 are provided to communicate with the well annulus below the packing element 16. A valve sleeve 27 is located within the passage 24 adjacent to the side ports 26 and is arranged for movement between various rotational positions about the longitudinal axis of the mandrel 11 to control fluid flow from the passage 24 through the side ports 26. In one rotational position, lateral ports 28 in the valve sleeve 27 are aligned with the side ports 26 in the valve body 13 to permit fluid flow. In other rotational positions of the valve sleeve 27,

. the ports 26 and 28 are not in registry and the passage 24 is closed to fluid flow in either direction.

As shown in FIG. 2, the valve sleeve 27 is generally tubular in form and has appropriate external grooves for a seal structure which can include upper and lower annular seals 29 and 30 which are connected by vertically extending seals 31 and 32 located on either side of the ports 28. With this type of seal configuration, the side seals 31 and 32 together with the seal portions 33 and 34 above and below the ports 28 prevent fluid flow through the ports, while the entirety of the upper and lower seals 29 and 30 precludes flow through the body ports 26. In the alternative, it will be appreciated that the seal arrangement could include face seals which surround the sleeve ports 28 to prevent flow in either direction through the sleeve ports, along with upper and lower annular sleeve seals above and below the face seals to prevent flow in either direction through the body ports 26. Radially inwardly extending pins or lugs 35 on the valve sleeve 27 provide a means for applying rotation force or torque to the valve sleeve 27 to rotate it between its various positions.

With further reference to FIG. 1A, the setting tool assembly A includes a central mandrel 38 having an open bore 39 and which can be connected to the lower end of the tubing string 10 by a threaded collar 40 or the like. The lower end portion of the mandrel 38 is provided with a swivel connection 41 to a tubular extension assembly which includes an enlarged sub 42 located above the upper end of the packer mandrel 11 and a tubular valve actuator or operator which telescopes within the bore 12 of the packer mandrel. The sub 42 and the operator 45 are connected together by a left-hand threaded joint 43 in a fluid tight manner. A swivel sleeve 44 is coupled to the upper portion of the sub 42 and has an inwardly extending shoulder section 46 forming an annular space 47 which rotatably receives an outwardly extending annular flange 48 on the mandrel 38. Accordingly, it will be apparent that the operator 45 and sub 42 can turn or rotate relative to both the mandrel 38 and the tubing 10. Appropriate seals such as 0- rings 49 and 50 can be provided, the lower seal 50 preventing fluid leakage from the bore of the mandrel 38 at the swivel connection 41, and the upper seal 49 protecting the swivel connection from ambient well fluids and debris.

The operator 45 is telescoped within the bore of the packer mandrel 11 and has arcuate coupling lugs 52 which can engage within an elongate internal mandrel recess 53. The recess 53, shown in an inside developed view in FIG. 3, is open to the top of the packer mandrel 11 by vertically extending slots 54 and 55 located on circumferentially opposite sides of the bore of the mandrel. Thus, the coupling lugs 52 can be inserted into the recess 53 via the slots 54 and 55, and rotation of the operator 45 relative to the mandrel 11 will position the lugs 52 underneath mandrel shoulders 56 formed between the slots. With this relationship of parts, engagement of the coupling lugs 52 with the shoulders 56 will limit upward movement of the extension 45 relative to the mandrel 11, and engagement ofthe sub 42 with the upper end surface ofthe mandrel 11 will limit downward movement. Accordingly, when the lugs 52 are underneath the shoulders 56, the extension 45 is coupled for limited telescoping movement relative to the mandrel 11, and when the lugs are aligned with the slots 54, 55 the extension can be inserted within, or withdrawn from, the bore 12 of the mandrel 11.

The lower end portion of the operator 45 is constituted as a torque sleeve 60 coupled thereto by a threaded collar 61 or the like. The torque sleeve 60 has upwardly extending side guide slots 62 which are flared and open at the lower end of the sleeve 60. The slots 62 receive the valve sleeve lugs 35 so that rotation of the extension 45 will impart corresponding rotation to the valve sleeve 27. Each side slot 62, has a sufficient vertical extent whereby the operator 45 can be moved upwardly and downwardly a predetermined amount and still be corotatively coupled to the valve sleeve 27. The collar 61 can be terminated below an annular shoulder 65 on the operator 45 to provide an annular recess in which a seal structure 66 is located. The seal structur. 6, which can take many forms, is shown as one or more metallic rings 67 having inner and outer grooves which receive suitable seals 68 and 69. Thus arranged, the seal structure 66 prevents fluid leakage between the packer mandrel 11 and the operator 45 when the latter is telescoped within the former.

Upper slip segments 72 are mounted at the upper end portion of the packer mandrel 11 adjacent to the upper expander cone 17. The segments 72 have upward facing wickers or teeth 73 on their outer peripheries, as well as inner inclined surfaces 74 which are engageable with outer inclined surfaces 75 on the expander cone 17 for shifting the segments outwardly into gripping engagement with well casing. The extension sub 42 and the packer mandrel 11 are respectively provided with annular grooves 76 and 77 and the slip segments 72 can have corresponding shoulders 78 and 79 which engage within the grooves to limit vertical movement of the slip segments in their retracted positions as well as initially coupling the extension sub 42 in fixed relation to the packer mandrel 11. A retainer sleeve 80, which forms a part of the setting tool A, extends downwardly in encompassing relation over upper portion 81 of the slip segments to retain them inwardly iiiretracted positions as long as the retainer sleeve occupies the relative position shown in FIG 1A and 1B. lt will be appreciated that due to the engaging conditions of the shoulders 78 and 79 within the grooves 76 and 77, and to the holding action of the retainer sleeve 80, the slip segments 72 are quite rigidly held inwardly in retracted positions to prevent any likelihood of premature setting during lowering into a well.

Further to the setting tool assembly A, a control sleeve 88 (FIG. 1A) is slidably and corotatively secured to the operating mandrel 38 by splines 89 or the like. The control sleeve 88 is initially locked in an upper position on the mandrel 38 by several latch lugs 90 which engage in a mandrel detent 91. A drag mechanism 92 including a tubular cage 93 is initially secured in a lower position on the control sleeve by coengaging right-hand threads 94. Typical drag blocks 95 are carried by the cage 93 and are urged outwardlyby coil springs 96' to frictionally engage casing and resist motion in a conventional manner. An inner surface 97 on the cage 93 holds the latch lugs 90 inwardly in engagement with the mandrel detent 19 while the parts are in relative positions for lowering into a well bore.

The slip retainer sleeve extends downwardly from the cage 93 to encompass the upper end portions 81 of the upper slip segments 72 as was previously described. When desired, it will be appreciated that right-hand rotation of the operating mandrel 38 by the running-in string 10 will rotate the control sleeve 88 relative to the drag mechanism 92, and, due 'to the interengagement of the threads 94, cause the drag mechanism and the retainer sleeve 80 to feed upwardly along the control sleeve 88, thereby removing the retainer sleeve from encompassing relation to the upper portions of the slips 72. Upward feeding of the drag mechanism 92 will also position an internal cage recess 100 opposite the latch lugs and permit them to move outwardly and release from the mandrel detent 91, thereby permitting upward movement of the operating mandrel 38 relative to the control sleeve 88 and the drag mechanism 92.

A slip setting or holding sleeve 101 extends downwardly from the control sleeve 88 and terminates in spaced relation to upper portions 81 of the slips 72. When the retainer sleeve 80 is removed upwardly, the slips 72 can move outwardly to engage the well casing. Outward movement of the slips will, of course, remove the shoulders 78 and 79 from engagement with the mandrel and sub grooves 76 and 77 and thereby un-' couple the packer mandrel 11 from the operator assembly.- With this condition of parts, the extension 45 can telescope upwardly relative to the packer mandrel 11 until the coupling lugs 52 engage the recess shoulders 56. Then upward extension movement will shift the packer mandrel 11 upwardly rela tive to the setting sleeve 101, the latter part not moving upward by virtue of the engagement of the friction drag blocks with the well casing. Accordingly, it will be appreciated that the slip segments 72 cannot move upwardly due to the holding action of the setting sleeve 101, and that the expander cone 17 can be moved upwardly and behind the slips 72 to shift them outwardly into firm anchoring engagement with the well casing. Once the upper slips 72 are set, the expander cone 17 cannot move any further upwardly and continued upward movement of the mandrel'll will advance the lower cone 5 toward the upper cone to expand the packing 16. The lower slips 1,4 are shifted over the lower expander cone and outwardly into gripping engagement with the well casing. The ratchet ring will lock the parts in expanded position in conventional manner. l 7

In response to upward and downward motions of the operator assembly 45 relative to the packer mandrel l1 occasioned by like motionsimparted to the running in string 10 once the packer B is set, the. operator is caused to rotate through various rotational positions due to-interengagement of index pins104, extending inwardly within the bore of the mandrel 11, with a slot or guide system-1 05 to be described below.

7 Rotation of the operator 45 within the packer mandrel 11 .serves the primary function of selectively rotating the valve ranged around the circumference of the extension 45, for purposes of brevity, only one-half of the total slot system structure' will be described and it will be appreciated that each slot portion mentioned hereafter has an' identical counterpart location on theopposite'side of the extension. Between these entrance and exit slots 106 and 107 are. upper pockets 108 and 109, theleft upper pocket 108 being located, for example,

. about 50 from entrance and exit slot 106 and the right upper pocket 109 being located, for example, about 40? from entrance and exit slot 107. Anintermediate pocket 110-is located between the upper pockets 108 and 109 and can be located about 50 from the left upper pocket 108. The entrance and'exit slot 106 is connected to the upper pocket 108 by a channel 111 which extends upwardly and to the right, and the upper pocket 108 is connected to the intermediate pocket 110 by a channel 112 which extends downwardly and to the right. The intermediate pocket 110 is connected to the upper pocket 109 by a channel 113 which extends upwardly and to the right like channel 111, and the upper pocket 109 is connected to the entrance-and exit slot 107 by a channel 114 which extends downwardlyand to the right like channel 112. The intersections of the channels 111 and 112, and 113 and 114, are located somewhat to the left of the respective centers of the upper pockets 108and 109 so that the index pin 104 is constrained to enter the channel 112 when leaving pocket 108, and channel 114 when leaving pocket 109. Moreover, the intersection of channels 112 and 113 is located somewhat to the-left of the intermediate pocket 110 so that the index pin 104 will enter the channel 113 when leaving the pocket 110.

it will be apparent that the slot system 105 provides a guide way in which the pins 104engage to cause a predetermined tion of the extension 45 for a total of 180. Each increment of extension rotation will cause a corresponding amount of rotation of the valvesleeve 27 by virtue of engagement of the valve sleeve lugs 35 with the sidewalls of the slots 62 in the torque sleeve 60.

The coupling lugs 52 on the operator 45 are vertically aligned relative to the entrance and exit slots 106 and 107, and the mandrel recess openings 54 and 55 (FIG. 3) aligned relative to the index pins 104, such that when the index pins 104 engage within the entrance and exit slots, the coupling lugs 52 are vertically aligned with the mandrel recess openings and can readily pass into, and out of, the mandrel recess 53. When the index pins 104 engage the upper wall surfaces 115 of the channels 111 which are inclined upwardly and to the right, the operator 45 is caused to rotate or swivel in the clockwise direction to position the coupling lugs 52 underneath the mandrel shoulders 56. The lugs 52 will remain in positions underneath the mandrel shoulders 56 as long as the entrance and exit slots .106, 107 are not aligned with the index pins 104. The entrance and exit slots 106 and 107 are also circumferentially located relative to the torque sleeve slots 60 so that when the index pins 104 are within the slots 106 and 107, and thus when the coupling lugs 52 can pass through the recess openings 54 and 55, the valve sleeve 27 is always in a closed rotational position. The bosses 120 formed between the entrance and exit slots 106 and 107 can have lower converging cam surfaces 121 and 122 to insure that the mandrel index pins 104 will enter one or the other of the slots 106 and 107 regardless of the initial rotational position of the operator 45 relative to the packer mandrel 11' when the operator is inserted. Moreover, the pins 104 can have flattenedperipheral portions to reduce bearing loads as the pins work within the slot system 105.

Should it ever be desired to disconnect the setting tool A from the well packer B, leavingthe operator 45 within the bore of the packer mandrel 11, for example, where the operator has become lodged within the mandrel by sedimentation or junk in the well, a safety feature in accordance with the present invention is provided for this purpose. With particular reference to FIG. 5, the tubular section 48a below the flange 48 is provided with a plurality of axially extending splines 125 located at circumferentially spaced points around the section. An annular clutch ring 126 is slidably received on the section 48 and has internal splines 127 that mesh with the splines 125 on the section 48. A coil spring 128 is located between the flange 48 and the clutch ring 126 and urges the clutch ring downwardly. The lower end of the clutch ring 126 has teeth 129 formed thereon which cooperate with companion teeth 130 formed on the sub 42. The teeth 129 and 130 have axially extending surfaces 131 and 132 that are engageable to transmit right-hand torque from the setting tool mandrel 38 to the sequence of rotational movements of the operator 45 relative to the mandrel 11in response to upward and downward motions of theextension. Thus, movement of the index pin 104 from entrance and exit slot 106 to the left upper pocket 108 will cause the extension 45 to rotate about 50 in a clockwise direction (viewed from above) within the packer mandrel 11,

such rotation being occasioned by engagement of the upper inclined wall 115 of channel 111 with the index pin. Movement of the index pin 104 from the upperpocket 108 to the pocket 110 will causeanother 50 rotation of the extension 45 sub 42. However, inclined surfaces 133 and 134 are provided on the teeth 129 and 130 so that in response to clockwise rotation of the operator 45 and the sub 42 relative to the mandrel 11, the teeth 129 and 130 will ratchet past each other.

OPERATION In operation, the parts are assembled as shown in the drawings with the operator 45 t'elescoped within the packer mandrel 11. The slips 15 and 72 and the packing 16 are in normally retracted positions, the upper slips 72 being retained inwardly by the retainer sleeve 80. The drag blocks can slide along in frictional engagement with the well casing as the tool is lowered into a well bore to setting depth. The initial insertion of the operator 45 within the mandrel 11 will cause the index pins 104 to rotate the operator until the pins are in the left upper pockets 108 of the slot system, corresponding to the open condition of the valve sleeve 27. Thus the pipe string 10 can fill with well fluid as the tool is lowered to setting depth.

When it is desired to set the packet- B, the running-in string '10 is first rotated a number of turns to the right. Since the drag mechanism 92 cannot rotate due to engagement of the drag blocks 95 with the casing, the control sleeve 88 will be rotated relative to the drag mechanism 92 with resultant upward feeding of the retainer sleeve 80 out of encompassing relation to the upper portions 81 of the upper slips 72. In actuality, the entire apparatus in the well except for the drag mechanism 92 and retainer sleeve 80 will be rotated by the running-in string 10. When the retainer sleeve 80 moves sufficiently upwardly, the slips 77 are free to move outwardly and the lower end of the setting sleeve 101 is cleared for engagement with upper end surfaces of the slips 72. The cage recess 100 is now positioned adjacent to the latch lugs 90 so that the lugs can move outwardly and release from the mandrel detent 91. The operating mandrel 38 is thus free to be moved upwardly relative to the control sleeve 88, the drag mechanism 92 and the setting sleeve 101.

The running-in string 10 is then elevated to set the packer B. When the slips 72 are released, as previously described, the extension 45 can move upwardly to a limited extent relative to the packer mandrel 11. As this relative movement occurs, the operator 45 is rotated as the index pins 104 move within the intermediate pockets 110, or positions E, FIG. 4. This rotation of the extension also positions the coupling lugs 52 underneath and in engagement with the mandrel recess shoulders 56, the lugs moving from positions G to positions H as shown in FIG. 3. This movement also rotates the valve sleeve 27 to closed position. The inclined surfaces 133 and 134 on the clutch ring teeth 129 and 130 cause the clutch ring 126 to shift upwardly so that the teeth ratchet past each other easily. Accordingly, it will be apparent that the operator 45 can rotate freely in a clockwise direction relative to the mandrel 11.

Inasmuch as the coupling lugs 52 are underneath the mandrel shoulders 56, continued upward movement of the extension 45 will elevate the packer mandrel 11, and thus the upper expander cone 17, toward the lower end surface of the setting sleeve 101. The slips 72 will thus be shifted outwardly into gripping engagement with the casing, the holding force of the drag blocks 95 being transmitted through the cage 93, threads 94, control sleeve 88 to the setting sleeve 101 to prevent its upward movement. The slips 72 will accordingly be held against upward movement by the setting sleeve 101 and sufficient upward movement of the packer mandrel 11 will bring the expander cone 17. behind the slips 72 to shift them outwardly into gripping engagement with the casing. When the upper slips 72 grip the casing, the upper expander cone 17 cannot move any further upwardly, and continued upward movement of the packer mandrel 11 will cause expansion of the packing element 16 and then shifting of the lower slips 14 over the lower expander cone 15. The external body teeth 21 will ratchet through the ratchet ring and the ring will trap the mandrel 11 in the highest position to which it is moved. Accordingly, the packing and slips are locked in expanded positions and when a predetermined upward strain is taken on the running-in string, the packer B will be firmly set.

After thus setting the packer B, the weight of the running-in string 10 is slacked off. This will occasion downward movement of the operator 45 within the packer mandrel 11 with consequent rotation of the operator and the valve sleeve 27 until the index pins 104 are within the right upper pockets 109 of the slot system, positions F in FIG. 4. The valve sleeve 27 is still in one of its closed rotational positions. Accordingly, the running-in string 10 is closed-off at its lower end and can be pressure tested for leakage at this time. The weight of the running-in string 10 can be conveniently imposed upon the packer B so that pressurizing the string 10 will not cause the operator to be lifted upwardly by the pressure. The feature of being able to impose tubing weight on the tool when testing tubing is an important advantage over packers of this type having reciprocating sleeve valves because the imposition of tubing weight may open the valve systems ofthese packers.

After such testing, the running-in string 10 is simply picked up atthe surface to disengage the operator 45 from within the bore of the packer mandrel 117 As the operator 45 is moved upwardly, the index pins 104 will cause the operator and the valve sleeve 27 to rotate again as the index pins move within the entrance and exit slots 107. The valve sleeve 27 is still closed. In this relative rotational position of parts the coupling lugs 52 are moved from positions K, FIG. 3, into vertical alignment with the mandrel recess openings 54, 55. Accordingly, the operator 45 is conditioned to be'withdrawn from the bore of the packer mandrel 11. It will be noted that whenever the operator 45 is withdrawn, the valve sleeve 27 is always left in a closed rotational position, whereby the well packer B completely bridges the well bore to prevent fluid flow in either longitudinal direction.

To perform a pressure operation such as squeeze cementing, the operator 45 is reinserted within the bore 12 of the packer mandrel 11 by downward movement of the running-in string 10. Regardless of the initial random rotational position of the operator 45, the bosses 120 and the lower cam surfaces 121 and 122 will cooperate with the index pins 104 to properly orient the operator 45 such that the index pins are vertically aligned within the entrance and exit slots 106 and 107. With the slots 106 and 107 thus aligned, the coupling lugs 52 are also aligned with the mandrel recess openings 54, 55 and the side slots 62 in the torque sleeve 60 are properly positioned with respect to the valve sleeve lugs 35 so that the torque sleeve can be lowered inside the valve sleeve 27. When the operator 45 has moved sufficiently downwardly within the bore of the packer mandrel 11, the index pins 104 will engage the upper inclined surfaces of the channels 111 and cause the extension and the valve sleeve 27 to rotate during further downward movement until the index pins are within the left upper pockets l08fAs this rotation occurs, the valve sleeve ports 28 will become radially aligned with the valve body ports 26 to open the valve. The coupling lugs 52 are also rotated to positions within the mandrel recess 53 such that the lugs are underneath the recess shoulders 56. With the valve open, cement slurry or other fluid can be displaced through the running-in string 10 and out into the well bore below the packer.

When sufficient displacement has occurred and it is desired to trap the squeeze, e.g., to retain the cement slurry at developed pressures below the packer B, the valve sleeve 27 can be moved to a rotationally closed position by simply picking the running-in string 10 upwardly to index the operator 45 until the index pins 104 are within the intermediate pockets 110, thereby rotating the valve sleeve 27 to closed position. The coupling lugs 52 will engage the mandrel shoulders 56 to positively prevent separation of the operator-45 from the mandrel 11, thereby enabling complete control 'of tubing and annulus pressures. Thus it will be appreciated that adequate annulus pressures can be maintained to prevent dumping cement into well bore when the operator 45 is purposely disengaged. The operator 45 can be withdrawn from the packer mandrel 11, leaving the valve sleeve 27 in closed position, by imparting a pair of vertical motions to the running-in string 10, one downward, and one upward. The corresponding reciprocation of the operator 45 will cause the index pins 104 to traverse the channels 113 and 114 and into the entrance and exit slots 106, whereupon the coupling lugs 52 are vertically aligned with the mandrel recess openings 54, 55 and the operator 45 is free for upward movement, leaving the valve sleeve 27 in closed condition. The setting tool A can be withdrawn from the well, or conventional circulation or reverse circulation procedures can be undertaken. Of course, the operator 45 can be reinserted within the packer mandrel 11 for further operations as desired.

In the event that the operator 45 should become lodged within the mandrel bore 12 for any reason, the safety coupling of the present invention can be operated to release the :pipe string 10 in a convenient manner. With a small strain being placed in the pipe string 10 by appropriate manipulation at the surface, the pipe string is rotated to the right. The axially disposed teeth surfaces 131 and 132 on the clutch ring 126 and the sub 42 respectively, will engage so that torque is transmitted through the splines 125, 127, the clutch ring 126 and'to the sub 42. it will be recalled that the threads 43 connecting the operator 45 to the sub 42 are left-hand, so that right-hand rotation will unthread the sub from the operator. This will release everything above the operator 45 for withdrawal from the well bore. 1

It will now be apparent that .a new and improved safety coupling has been disclosed that is positive and reliable in operation. Since certain changes or modifications may be made in the present invention'by those skilled in the art without departing from the concepts involved, it is intended that the appended claims cover all such changes or modifications falling within the true spirit and scope of the present invention. i

Iclaim:

1. Apparatus for use in a well comprising: a first member adapted for connection to a pipe string extending upwardly to the top of the well; a second member coupled to said first member for rotation relative thereto; clutch means, including a clutch element coupled to said first member and having drive means engageable with driven means on said second member, for enabling rotation of said second member relative to said first member inone direction and for preventing rotation of said first member relative to said second member in said one direction; and a third member connected to said second member by a rotationally releasable means that is releasable in response to rotation of said second member by said first member relative to said third member in said one direction. 2. The apparatus of claim 1 further including means for corotatively and slidably securing said clutch element to'said firstmember. 3 i l 1 I '4 3. .The apparatus of claim further including-yieldable means for urging said drive means toward said driven means.

4. The apparatus of claim I wherein said drive means and said driven means are constituted by teeth having longitudinally disposed surfaces for preventing rotation of said first member relative to said second member in said one direction and inclined surfaces for enabling rotation of said second member relative to said first member in said one direction 5. The apparatus of claim 4 further including spline means for corotatively and slidably securing said clutch element to said first member.

6. The apparatus of claim 5 further including spring means for urging said teeth into mesh with one another.

7. Apparatus for use in releasably coupling relatively rotatable members to an anchored member in a well bore comprising: a first member adapted to be connected to a pipe string extending upwardly to the top of the well; a second member having a swivel coupling with said first member; first clutch means on said first member cooperablc with second clutch means on said second member to enable rotation of said second member relative to said first member in one direction and to prevent rotation of said first member relative to said second member in said one direction; means for preventing relative rotation between said first clutch means and said first member; a third member adapted to be connected to said anchored member; and rotationally releasable meansfor connecting said second member to said third member that is releasable in response to rotation insaid one direction.

8. The apparatus of claim 7 wherein said one direction is the right-hand direction.

9. The apparatus of claim 8 wherein said rotationally I releasable means is a left-hand thread. v 

1. Apparatus for use in a well comprising: a first member adapted for connection to a pipe string extending upwardly to the top of the well; a second member coupled to said first member for rotation relative thereto; clutch means, including a clutch element coupled to said first member and having drive means engageable with driven means on said second member, for enabling rotation of said second member relative to said first member in one direction and for preventing rotation of said first member relative to said second member in said one direction; and a third member connected to said second member by a rotationally releasable means that is releasable in response to rotation of said second member by said first member relative to said third member in said one direction.
 2. The apparatus of claim 1 further including means for corotatively and slidably securing said clutch element to said first member.
 3. The apparatus of claim 2 further including yieldable means for urging said drive means toward said driven means.
 4. The apparatus of claim 1 wherein said drive means and said driven means are constituted by teeth having longitudinally disposed surfaces for preventing rotation of said first member relative to said second member in said one direction and inclined surfaces for enabling rotation of said second member relative to said first member in said one direction.
 5. The apparatus of claim 4 further including spline means for corotatively and slidably securing said clutch element to said first member.
 6. The apparatus of claim 5 further including spring means for urging said teeth into mesh with one another.
 7. Apparatus for use in releasably coupling relatively rotatable members to an anchored member in a well bore comprising: a first member adapted to be connected to a pipe string extending upwardly to the top of the well; a second member having a swivel coupling with said first member; first clutch means on said first member cooperable with second clutch means on said second member to enable rotation of said second member relative to said first member in one direction and to prevent rotation of said first member relative to said second member in said one direction; means for preventing relative rotation between said first clutch means and said first member; a third member adapted to be connected to said anchored member; and rotationally releasable means for connecting said second member to said third member that is releasable in response to rotation in said one direction.
 8. The apparatus of claim 7 wherein said one direction is the right-hand direction.
 9. The apparatus of claim 8 wherein said rotationally releasable means is a left-hand thread. 